There are many variables to consider to ensure a usable well bore is constructed when using cutting systems and processes for the drilling of well bores or the cutting of formations for the construction of tunnels and other subterranean earthen excavations. Many variables, such as formation hardness, abrasiveness, pore pressures, and formation elastic properties affect the effectiveness of a particular drill bit in drilling a well bore. Additionally, in drilling well bores, formation hardness and a corresponding degree of drilling difficulty may increase exponentially as a function of increasing depth. The rate at which a drill bit may penetrate the formation typically decreases with harder and tougher formation materials and formation depth.
When the formation is relatively soft, as with shale, material removed by the drill bit will have a tendency to reconstitute onto the teeth of the drill bit. Build-up of the reconstituted formation on the drill bit is typically referred to as “bit balling” and reduces the depth that the teeth of the drill bit will penetrate the bottom surface of the well bore, thereby reducing the efficiency of the drill bit. Particles of a shale formation also tend to reconstitute back onto the bottom surface of the bore hole. The reconstitution of a formation back onto the bottom surface of the bore hole is typically referred to as “bottom balling”. Bottom balling prevents the teeth of a drill bit from engaging virgin formation and spreads the impact of a tooth over a wider area, thereby also reducing the efficiency of a drill bit. Additionally, higher density drilling muds that are required to maintain well bore stability or well bore pressure control exacerbate bit balling and the bottom balling problems.
When the drill bit engages a formation of a harder rock, the teeth of the drill bit press against the formation and densify a small area under the teeth to cause a crack in the formation. When the porosity of the formation is collapsed, or densified, in a hard rock formation below a tooth, conventional drill bit nozzles ejecting drilling fluid are used to remove the crushed material from below the drill bit. As a result, a cushion, or densification pad, of densified material is left on the bottom surface by the prior art drill bits. If the densification pad is left on the bottom surface, force by a tooth of the drill bit will be distributed over a larger area and reduce the effectiveness of a drill bit.
There are generally two main categories of modern drill bits that have evolved over time. These are the commonly known fixed cutter drill bit and the roller cone drill bit. Additional categories of drilling include percussion drilling and mud hammers. However, these methods are not as widely used as the fixed cutter and roller cone drill bits. Within these two primary categories (fixed cutter and roller cone), there are a wide variety of variations, with each variation designed to drill a formation having a general range of formation properties.
The fixed cutter drill bit and the roller cone type drill bit generally constitute the bulk of the drill bits employed to drill oil and gas wells around the world. When a typical roller cone rock bit tooth presses upon a very hard, dense, deep formation, the tooth point may only penetrate into the rock a very small distance, while also at least partially, plastically “working” the rock surface. Under conventional drilling techniques, such working the rock surface may result in the densification as noted above in hard rock formations.
With roller cone type drilling bits, a relationship exists between the number of teeth that impact upon the formation and the drilling RPM of the drill bit. A description of this relationship and an approach to improved drilling technology is set forth and described in U.S. Pat. No. 6,386,300 issued May 14, 2002, incorporated herein by reference for all purposes. The '300 patent discloses the use of solid material impactors introduced into drilling fluid and pumped though a drill string and drill bit to contact the rock formation ahead of the drill bit. The kinetic energy of the impactors leaving the drill bit is given by the following equation: Ek=½ Mass(Velocity)2. The mass and/or velocity of the impactors may be chosen to satisfy the mass-velocity relationship in order to structurally alter the rock formation.